Process and apparatus for removal of heavy polynuclear aromatics in a hydrocracking process

ABSTRACT

Processes and apparatuses are disclosed for removing heavy polynuclear aromatic compounds from a hydrocracked stream comprising passing at least a portion of the hydrocracked stream to a fractionation column to provide a plurality of fractionator product streams and a fractionator bottoms stream comprising unconverted hydrocarbons. A first stream and a second stream are taken from the fractionator bottoms stream. The first stream is passed through a heavy polynuclear aromatic adsorption zone to obtain a treated bottoms stream having a reduced concentration of heavy polynuclear aromatic compounds. The second stream is bypassed around the heavy polynuclear aromatic adsorption zone. Finally, the treated bottoms stream and the bypassed second stream are hydrocracked.

CROSS-REFERENCE TO RELATED APPLICATION

This application claims priority from Provisional Application No.62/373,189 filed Aug. 10, 2016, the contents of which cited applicationare hereby incorporated by reference in its entirety.

FIELD

The technical field generally relates to processes and apparatuses forhydrocracking of hydrocarbon streams. More particularly, the technicalfield relates to an improved process and apparatus for removing heavypolynuclear aromatics from a hydrocracking process.

BACKGROUND

Hydroprocessing can include processes which convert hydrocarbons in thepresence of hydroprocessing catalyst and hydrogen to more valuableproducts. Hydrocracking is a hydroprocessing process in whichhydrocarbons crack in the presence of hydrogen and hydrocrackingcatalyst to lower molecular weight hydrocarbons. Depending on thedesired output, a hydrocracking unit may contain one or more fixed bedsof the same or different catalyst. Hydrotreating is a process in whichhydrogen is contacted with hydrocarbon in the presence of hydrotreatingcatalysts which are primarily active for the removal of heteroatoms,such as sulfur, nitrogen and metals from the hydrocarbon feedstock. Inhydrotreating, hydrocarbons with double and triple bonds may besaturated. Aromatics may also be saturated. Some hydrotreating processesare specifically designed to saturate aromatics.

Often, heavy polynuclear aromatic (may be abbreviated as “HPNA”)compounds may be a secondary product of a hydrocracking processparticularly of high conversion hydrocracking units. Recyclingunconverted oil to increase yields of distillate product can result inan accumulation of HPNA compounds in the unconverted oil. AccumulatedHPNA compounds in the recycle oil may deposit on the catalyst as coke,which may degrade catalyst performance and result in shorter catalystcycle length. In addition HPNA can deposit on equipment in the coolersections of the process. Production of undesired HPNA compounds can bemore pronounced for hydrocracking units processing heavier feeds. Thus,it would be desirable to remove the HPNA compounds from the unconvertedoil so as to minimize the catalyst deactivation.

One option is to lower conversion by bleeding a portion of theunconverted oil to remove accumulated HPNA compounds. Unfortunately,this is often undesirable due to economic and logistic considerationsbecause of yield loss and lack of market for the unconverted oil.

Thus, there is a desire to provide an improved process that providesimproved performance and prevents HPNA compounds accumulation withoutthe shortcomings discussed above. Furthermore, other desirable featuresand characteristics of the present invention will become apparent fromthe subsequent detailed description and the appended claims, taken inconjunction with the accompanying Figures and this background.

BRIEF SUMMARY

Various embodiments contemplated herein relate to processes andapparatuses for removing HPNA's from a hydrocracking process. Theexemplary embodiments taught herein provide an improved process andapparatus for removing HPNA from a two-stage or a single-stagehydrocracking process.

In accordance with an exemplary embodiment, a process is provided for ofremoving HPNA compounds from a hydrocracked stream comprising passing atleast a portion of the hydrocracked stream to a fractionation column toprovide a plurality of fractionator product streams and a fractionatorbottoms stream comprising unconverted hydrocarbons. A first stream and asecond stream are taken from the fractionator bottoms stream. The firststream is passed through a HPNA adsorption zone to obtain a treatedbottoms stream having a reduced concentration of HPNA compounds. Thesecond stream is bypassed around the HPNA adsorption zone. Finally, thetreated bottoms stream and the bypassed second stream are hydrocracked.

In accordance with another exemplary embodiment, a process is providedfor upgrading a hydrocarbon stream comprising passing the hydrocarbonfeedstream to a first hydrocracking reactor, the first hydrocrackingreactor containing at least one bed of a first hydrocracking catalyst,wherein the hydrocarbon feedstream is contacted with the firsthydrocracking catalyst under first hydrocracking conditions in thepresence of hydrogen to produce a first hydrocracked effluent stream. Atleast a portion of the first hydrocracked effluent stream is passed to afractionation column to provide a plurality of fractionator productstreams and a fractionator bottoms stream comprising unconvertedhydrocarbons. The fractionator bottoms stream is split to provide afirst stream and a second stream. The first stream is passed through aHPNA adsorption zone to obtain a treated bottoms stream having a reducedconcentration of HPNA compounds. The second stream is bypassed aroundthe HPNA adsorption zone. The treated bottoms stream and the bypassedsecond stream are passed to a second hydrocracking reactor, the secondhydrocracking reactor containing at least one bed of a secondhydrocracking catalyst, wherein the treated bottoms stream and thebypassed second stream are contacted with a second hydrocrackingcatalyst under second hydrocracking conditions in the presence ofhydrogen to provide a second hydrocracked effluent stream.

In accordance with yet another exemplary embodiment, an apparatus isprovided for removing HPNA compounds from a hydrocracked streamcomprising a fractionation column in communication with a hydrocrackedeffluent line to provide a plurality of fractionator product streams anda fractionator bottoms stream in a fractionator bottoms line. A firstfractionator bottoms line is fluidly connected to the fractionatorbottoms line. A second fractionator bottoms line is fluidly connected tothe fractionator bottoms line. A HPNA adsorption zone is in downstreamcommunication with the first fractionator bottoms line to provide atreated bottoms stream in a treated bottoms line having a reducedconcentration of HPNA compounds. A hydrocracking reactor incommunication with the treated bottoms line and the second fractionatorbottoms line, the second fractionator bottoms line bypassing the HPNAadsorption zone.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic drawing of a two-stage hydrocracking unit.

FIG. 2 is a schematic drawing of a single-stage hydrocracking unit.

DEFINITIONS

The term “communication” means that material flow is operativelypermitted between enumerated components.

The term “downstream communication” means that at least a portion ofmaterial flowing to the subject in downstream communication mayoperatively flow from the object with which it communicates.

The term “upstream communication” means that at least a portion of thematerial flowing from the subject in upstream communication mayoperatively flow to the object with which it communicates.

The term “direct communication” means that flow from the upstreamcomponent enters the downstream component without undergoing acompositional change due to physical fractionation or chemicalconversion.

The term “column” means a distillation column or columns for separatingone or more components of different volatilities. Unless otherwiseindicated, each column includes a condenser on an overhead of the columnto condense and reflux a portion of an overhead stream back to the topof the column and a reboiler at a bottom of the column to vaporize andsend a portion of a bottoms stream back to the bottom of the column.Absorber and scrubbing columns do not include a condenser on an overheadof the column to condense and reflux a portion of an overhead streamback to the top of the column and a reboiler at a bottom of the columnto vaporize and send a portion of a bottoms stream back to the bottom ofthe column. Feeds to the columns may be preheated. The overhead pressureis the pressure of the overhead vapor at the vapor outlet of the column.The bottom temperature is the liquid bottom outlet temperature. Overheadlines and bottoms lines refer to the net lines from the columndownstream of any reflux or reboil to the column unless otherwiseindicated. Stripping columns omit a reboiler at a bottom of the columnand instead provide heating requirements and separation impetus from afluidized inert vaporous media such as steam.

As used herein, the term “True Boiling Point” (TBP) means a test methodfor determining the boiling point of a material which corresponds toASTM D-2892 for the production of a liquefied gas, distillate fractions,and residuum of standardized quality on which analytical data can beobtained, and the determination of yields of the above fractions by bothmass and volume from which a graph of temperature versus mass %distilled is produced using fifteen theoretical plates in a column witha 5:1 reflux ratio.

As used herein, the term “T5” or “T95” means the temperature at which 5volume percent or 95 volume percent, as the case may be, respectively,of the sample boils using ASTM D-86.

As used herein, the term “diesel boiling range” means hydrocarbonsboiling in the range of between about 132° C. (270° F.) and the dieselcut point between about 343° C. (650° F.) and about 399° C. (750° F.)using the TBP distillation method.

As used herein, the term “separator” means a vessel which has an inletand at least an overhead vapor outlet and a bottoms liquid outlet andmay also have an aqueous stream outlet from a boot. A flash drum is atype of separator which may be in downstream communication with aseparator which latter may be operated at higher pressure.

As used herein, the term “zone” can refer to an area including one ormore equipment items and/or one or more sub-zones. Equipment items caninclude one or more reactors or reactor vessels, heaters, exchangers,pipes, pumps, compressors, controllers and columns. Additionally, anequipment item, such as a reactor, dryer, or vessel, can further includeone or more zones or sub-zones.

As used herein, the term “HPNA” typically refer to compounds with six ormore aromatic rings and often refer to compounds with eleven or morearomatic rings and typically produced in a hydrocracking reaction zone.

DETAILED DESCRIPTION

The following detailed description is merely exemplary in nature and isnot intended to limit the various embodiments or the application anduses thereof. Furthermore, there is no intention to be bound by anytheory presented in the preceding background or the following detaileddescription. The Figures have been simplified by the deletion of a largenumber of apparatuses customarily employed in a process of this nature,such as vessel internals, temperature and pressure controls systems,flow control valves, recycle pumps, etc. which are not specificallyrequired to illustrate the performance of the invention. Furthermore,the illustration of the process of this invention in the embodiment of aspecific drawing is not intended to limit the invention to specificembodiments set out herein.

We have found that passing only a portion of the fractionator bottomsstream comprising unconverted oil relieves accumulation of HPNA in therecycle oil feed to the hydrocracking unit.

The subject apparatus and process passes only a portion of recycle oilthrough a HPNA adsorption zone while another portion of the recycle oilbypasses the HPNA adsorption zone and subsequently both the fractionsare hydrocracked.

The apparatus and process 10 for hydrocracking a hydrocarbon streamcomprise a first stage hydrocracking unit 12, a fractionation section 14and a second stage hydrocracking unit 150. A hydrocarbonaceous stream inhydrocarbon line 18 and a first stage hydrogen stream in a first stagehydrogen line 22 are fed to the first stage hydrocracking unit 12. Thefirst stage hydrocracking unit may include a hydrotreating reactor 30and a first hydrocracking reactor 40. The second stage hydrocrackingunit 150 may include a second hydrocracking reactor 170.

In one aspect, the process and apparatus described herein areparticularly useful for hydrocracking a hydrocarbon feed streamcomprising a hydrocarbonaceous feedstock. Illustrative hydrocarbonaceousfeed stocks include hydrocarbon streams having initial boiling points(IBP) above about 288° C. (550° F.), such as atmospheric gas oils,vacuum gas oil (VGO) having T5 and T95 between about 315° C. (600° F.)and about 600° C. (1100° F.), deasphalted oil, coker distillates,straight run distillates, pyrolysis-derived oils, high boiling syntheticoils, cycle oils, clarified slurry oils, deasphalted oil, shale oil,hydrocracked feeds, catalytic cracker distillates, atmospheric residuehaving an IBP at or above about 343° C. (650° F.) and vacuum residuehaving an IBP above about 510° C. (950° F.).

A hydrotreating hydrogen stream in a hydrotreating hydrogen line 24 maybe split off from the first stage hydrogen line 22. The firsthydrotreating hydrogen stream may join the hydrocarbonaceous stream infeed line 18 to provide a first hydrocarbon feed stream in a firsthydrocarbon feed line 26. The first hydrocarbon feed stream in the firsthydrocarbon feed line 26 may be heated by heat exchange with a firsthydrocracked effluent stream in line 48 and in a fired heater. Theheated first hydrocarbon feed stream in line 28 may be fed to ahydrotreating reactor 30.

Hydrotreating is a process wherein hydrogen is contacted withhydrocarbon in the presence of hydrotreating catalysts which areprimarily active for the removal of heteroatoms, such as sulfur,nitrogen and metals from the hydrocarbon feedstock. In hydrotreating,hydrocarbons with double and triple bonds may be saturated. Aromaticsmay also be saturated. Some hydrotreating processes are specificallydesigned to saturate aromatics.

The hydrotreating reactor 30 may comprise a guard bed of hydrotreatingcatalyst followed by one or more beds of higher quality hydrotreatingcatalyst. The guard bed filters particulates and picks up contaminantsin the hydrocarbon feed stream such as metals like nickel, vanadium,silicon and arsenic which deactivate the catalyst. The guard bed maycomprise material similar to the hydrotreating catalyst. Supplementalhydrogen in a first hydrotreating supplemental hydrogen line 31 may beadded at an interstage location between catalyst beds in thehydrotreating reactor 30.

Suitable hydrotreating catalysts for use in the hydrotreating reactorare any known conventional hydrotreating catalysts and include thosewhich are comprised of at least one Group VIII metal, preferably iron,cobalt and nickel, more preferably cobalt and/or nickel and at least oneGroup VI metal, preferably molybdenum and tungsten, on a high surfacearea support material, preferably alumina. Other suitable hydrotreatingcatalysts include zeolitic catalysts. In the high sulfur and nitrogenenvironment of the hydrotreating reactor 30, noble metal catalysts wouldbe discouraged. More than one type of hydrotreating catalyst may be usedin the hydrotreating reactor 30. The Group VIII metal is typicallypresent in an amount ranging from about 2 to about 20 wt %, preferablyfrom about 4 to about 12 wt %. The Group VI metal will typically bepresent in an amount ranging from about 1 to about 25 wt %, preferablyfrom about 2 to about 25 wt %.

Preferred reaction conditions in the hydrotreating reactor 30 include atemperature from about 290° C. (550° F.) to about 455° C. (850° F.),suitably 316° C. (600° F.) to about 427° C. (800° F.) and preferably343° C. (650° F.) to about 399° C. (750° F.), a pressure from about 2.1MPa (gauge) (300 psig), preferably 4.1 MPa (gauge) (600 psig) to about20.6 MPa (gauge) (3000 psig), suitably 12.4 MPa (gauge) (1800 psig),preferably 6.9 MPa (gauge) (1000 psig), a liquid hourly space velocityof the fresh hydrocarbonaceous feedstock from about 0.1 hr⁻¹, suitably0.5 hr⁻¹, to about 10 hr⁻¹, preferably from about 1.5 to about 8.5 hr⁻¹,and a hydrogen rate of about 168 Nm³/m³ (1,000 scf/bbl), to about 1,011Nm³/m³ oil (6,000 scf/bbl), preferably about 168 Nm³/m³ oil (1,000scf/bbl) to about 674 Nm³/m³ oil (4,000 scf/bbl), with a hydrotreatingcatalyst or a combination of hydrotreating catalysts.

The first hydrocarbon feed stream in the first hydrocarbon feed line 28is hydrotreated over the hydrotreating catalyst in the hydrotreatingreactor 30 to provide a hydrotreated hydrocarbon feed stream that exitsthe hydrotreating reactor 30 in a hydrotreating effluent line 32 whichcan be taken as a first hydrocracking feed stream. The hydrogen gasladen with ammonia and hydrogen sulfide may be removed from the firsthydrocracking feed stream in a separator, but the first hydrocrackingfeed stream is typically fed directly to the hydrocracking reactor 40without separation. The first hydrocracking feed stream may be mixedwith a first hydrocracking hydrogen stream in a first hydrocrackinghydrogen line 33 from the first stage hydrogen line 22 and is fedthrough a first inlet 32 i to the first hydrocracking reactor 40 to behydrocracked.

Hydrocracking is to a process in which hydrocarbons crack in thepresence of hydrogen to lower molecular weight hydrocarbons. The firsthydrocracking reactor 40 may be a fixed bed reactor that comprises oneor more vessels, single or multiple catalyst beds 42 in each vessel, andvarious combinations of hydrotreating catalyst, hydroisomerizationcatalyst and/or hydrocracking catalyst in one or more vessels. It iscontemplated that the first hydrocracking reactor 40 be operated in acontinuous liquid phase in which the volume of the liquid hydrocarbonfeed is greater than the volume of the hydrogen gas. The firsthydrocracking reactor 40 may also be operated in a conventionalcontinuous gas phase, a moving bed or a fluidized bed hydroprocessingreactor.

The hydrotreated first hydrocracking feed stream is hydrocracked over afirst hydrocracking catalyst in first hydrocracking catalyst beds 42 inthe presence of a first hydrocracking hydrogen stream from a firsthydrocracking hydrogen line 33 to provide a first hydrocracked effluentstream in line 48. Subsequent catalyst beds 42 in the hydrocrackingreactor may comprise hydrocracking catalyst over which additionalhydrocracking occurs to the hydrocracked stream. Hydrogen manifold 44may deliver supplemental hydrogen streams to one, some or each of thecatalyst beds 42. In an aspect, the supplemental hydrogen is added toeach of the catalyst beds 42 at an interstage location between adjacentbeds, so supplemental hydrogen is mixed with hydroprocessed effluentexiting from the upstream catalyst bed 42 before entering the downstreamcatalyst bed 42.

The first hydrocracking reactor 40 may provide a total conversion of atleast about 20 vol % and typically greater than about 60 vol % of thefirst hydrocracking feed stream in the hydrotreating effluent line 32 toproducts boiling below the diesel cut point. The first hydrocrackingreactor 40 may operate at partial conversion of more than about 30 vol %or full conversion of at least about 90 vol % of the feed based on totalconversion. The first hydrocracking reactor 40 may be operated at mildhydrocracking conditions which will provide about 20 to about 60 vol %,preferably about 20 to about 50 vol %, total conversion of thehydrocarbon feed stream to product boiling below the diesel cut point.

The first hydrocracking reactor 40 comprises a plurality of catalystbeds 42. If the hydrocracking unit 12 does not include a hydrotreatingreactor 30, the first catalyst bed in the hydrocracking reactor 40 mayinclude a hydrotreating catalyst for the purpose of saturating,demetallizing, desulfurizing or denitrogenating the first hydrocarbonfeed stream before it is hydrocracked with the first hydrocrackingcatalyst in subsequent vessels or catalyst beds 42 in the firsthydrocracking reactor 40. Otherwise, the first or an upstream bed in thefirst hydrocracking reactor 40.

The first hydrocracking catalyst may utilize amorphous silica-aluminabases or low-level zeolite bases combined with one or more Group VIII orGroup VIB metal hydrogenating components if mild hydrocracking isdesired to produce a balance of middle distillate and gasoline. Inanother aspect, when middle distillate is significantly preferred in theconverted product over gasoline production, partial or fullhydrocracking may be performed in the first hydrocracking reactor 40with a catalyst which comprises, in general, any crystalline zeolitecracking base upon which is deposited a Group VIII metal hydrogenatingcomponent. Additional hydrogenating components may be selected fromGroup VIB for incorporation with the zeolite base.

The zeolite cracking bases are sometimes referred to in the art asmolecular sieves and are usually composed of silica, alumina and one ormore exchangeable cations such as sodium, magnesium, calcium, rare earthmetals, etc. They are further characterized by crystal pores ofrelatively uniform diameter between about 4 and about 14 Angstroms(10⁻¹⁰ meters). It is preferred to employ zeolites having a relativelyhigh silica/alumina mole ratio between about 3 and about 12. Suitablezeolites found in nature include, for example, mordenite, stilbite,heulandite, ferrierite, dachiardite, chabazite, erionite and faujasite.Suitable synthetic zeolites include, for example, the B, X, Y and Lcrystal types, e.g., synthetic faujasite and mordenite. The preferredzeolites are those having crystal pore diameters between about 8 and 12Angstroms (10⁻¹⁰ meters), wherein the silica/alumina mole ratio is about4 to 6. One example of a zeolite falling in the preferred group issynthetic Y molecular sieve.

The natural occurring zeolites are normally found in a sodium form, analkaline earth metal form, or mixed forms. The synthetic zeolites arenearly always prepared first in the sodium form. In any case, for use asa cracking base it is preferred that most or all of the originalzeolitic monovalent metals be ion-exchanged with a polyvalent metaland/or with an ammonium salt followed by heating to decompose theammonium ions associated with the zeolite, leaving in their placehydrogen ions and/or exchange sites which have actually beendecationized by further removal of water. Hydrogen or “decationized” Yzeolites of this nature are more particularly described in U.S. Pat. No.3,100,006.

Mixed polyvalent metal-hydrogen zeolites may be prepared byion-exchanging first with an ammonium salt, then partially backexchanging with a polyvalent metal salt and then calcining. In somecases, as in the case of synthetic mordenite, the hydrogen forms can beprepared by direct acid treatment of the alkali metal zeolites. In oneaspect, the preferred cracking bases are those which are at least about10 wt %, and preferably at least about 20 wt %, metal-cation-deficient,based on the initial ion-exchange capacity. In another aspect, adesirable and stable class of zeolites is one wherein at least about 20wt % of the ion exchange capacity is satisfied by hydrogen ions.

The active metals employed in the preferred first hydrocrackingcatalysts of the present invention as hydrogenation components are thoseof Group VIII, i.e., iron, cobalt, nickel, ruthenium, rhodium,palladium, osmium, iridium and platinum. In addition to these metals,other promoters may also be employed in conjunction therewith, includingthe metals of Group VIB, e.g., molybdenum and tungsten. The amount ofhydrogenating metal in the catalyst can vary within wide ranges. Broadlyspeaking, any amount between about 0.05 wt % and about 30 wt % may beused. In the case of the noble metals, it is normally preferred to useabout 0.05 to about 2 wt % noble metal.

The method for incorporating the hydrogenation metal is to contact thebase material with an aqueous solution of a suitable compound of thedesired metal wherein the metal is present in a cationic form. Followingaddition of the selected hydrogenation metal or metals, the resultingcatalyst powder is then filtered, dried, pelleted with added lubricants,binders or the like if desired, and calcined in air at temperatures of,e.g., about 371° C. (700° F.) to about 648° C. (1200° F.) in order toactivate the catalyst and decompose ammonium ions. Alternatively, thebase component may first be pelleted, followed by the addition of thehydrogenation component and activation by calcining.

The foregoing catalysts may be employed in undiluted form, or thepowdered catalyst may be mixed and copelleted with other relatively lessactive catalysts, diluents or binders such as alumina, silica gel,silica-alumina cogels, activated clays and the like in proportionsranging between about 5 and about 90 wt %. These diluents may beemployed as such or they may contain a minor proportion of an addedhydrogenating metal such as a Group VIB and/or Group VIII metal.Additional metal promoted hydrocracking catalysts may also be utilizedin the process of the present invention which comprises, for example,aluminophosphate molecular sieves, crystalline chromosilicates and othercrystalline silicates. Crystalline chromosilicates are more fullydescribed in U.S. Pat. No. 4,363,718.

By one approach, the hydrocracking conditions may include a temperaturefrom about 290° C. (550° F.) to about 468° C. (875° F.), preferably 343°C. (650° F.) to about 445° C. (833° F.), a pressure from about 4.8 MPa(gauge) (700 psig) to about 20.7 MPa (gauge) (3000 psig), a liquidhourly space velocity (LHSV) from about 0.4 to less than about 2.5 hr⁻¹and a hydrogen rate of about 421 Nm³/m³ (2,500 scf/bbl) to about 2,527Nm³/m³ oil (15,000 scf/bbl). If mild hydrocracking is desired,conditions may include a temperature from about 315° C. (600° F.) toabout 441° C. (825° F.), a pressure from about 5.5 MPa (gauge) (800psig) to about 13.8 MPa (gauge) (2000 psig) or more typically about 6.9MPa (gauge) (1000 psig) to about 11.0 MPa (gauge) (1600 psig), a liquidhourly space velocity (LHSV) from about 0.5 to about 2 hr⁻¹ andpreferably about 0.7 to about 1.5 hr⁻¹ and a hydrogen rate of about 421Nm³/m³ oil (2,500 scf/bbl) to about 1,685 Nm³/m³ oil (10,000 scf/bbl).

The first hydrocracked effluent stream may exit the first hydrocrackingreactor 40 in line 48 and be separated in the fractionation section 14in downstream communication with the first hydrocracking reactor 40. Thefractionation section 14 comprises one or more separators andfractionation columns in downstream communication with the hydrocrackingreactor 40.

The first hydrocracked effluent stream in the first hydrocrackedeffluent line 48 may in an aspect be heat exchanged with the hydrocarbonfeed stream in line 26 to be cooled and be mixed with a secondhydrocracked effluent stream in a second hydrocracked effluent line 46.The combined hydrocracked effluent line 49 may deliver a combined streamto a hot separator 50. The hot separator separates the firsthydrocracked effluent stream and the second hydrocracked effluent streamto provide a hydrocarbonaceous, hot gaseous stream in a hot overheadline 52 and a hydrocarbonaceous, hot liquid stream in a hot bottoms line54. The hot separator 50 may be in downstream communication with thefirst hydrocracking reactor 40. The hot separator 50 operates at about177° C. (350° F.) to about 371° C. (700° F.) and preferably operates atabout 232° C. (450° F.) to about 315° C. (600° F.). The hot separator 50may be operated at a slightly lower pressure than the firsthydrocracking reactor 40 accounting for pressure drop throughintervening equipment. The hot separator 50 may be operated at pressuresbetween about 3.4 MPa (gauge) (493 psig) and about 20.4 MPa (gauge)(2959 psig). The hydrocarbonaceous, hot gaseous separated stream in thehot overhead line 52 may have a temperature of the operating temperatureof the hot separator 50.

The hot gaseous stream in the hot overhead line 52 may be cooled beforeentering a cold separator 56. As a consequence of the reactions takingplace in the first hydrocracking reactor 40 wherein nitrogen, chlorineand sulfur are removed from the feed, ammonia and hydrogen sulfide areformed. At a characteristic sublimation temperature, ammonia andhydrogen sulfide will combine to form ammonium bisulfide and ammonia,and chlorine will combine to form ammonium chloride. Each compound has acharacteristic sublimation temperature that may allow the compound tocoat equipment, particularly heat exchange equipment, impairing itsperformance. To prevent such deposition of ammonium bisulfide orammonium chloride salts in the hot overhead line 52 transporting the hotgaseous stream, a suitable amount of wash water may be introduced intothe hot overhead line 52 upstream of a cooler at a point in the hotoverhead line where the temperature is above the characteristicsublimation temperature of either compound.

The hot gaseous stream may be separated in the cold separator 56 toprovide a cold gaseous stream comprising a hydrogen-rich gas stream in acold overhead line 58 and a cold liquid stream in a cold bottoms line60. The cold separator 56 serves to separate hydrogen rich gas fromhydrocarbon liquid in the first hydrocracked effluent stream and thesecond hydrocracked effluent stream for recycle to the first stagehydrocracking unit 12 and the second stage hydrocracking unit 150 in thecold overhead line 58. The cold separator 56, therefore, is indownstream communication with the hot overhead line 52 of the hotseparator 50 and the first hydrocracking reactor 40. The cold separator56 may be operated at about 100° F. (38° C.) to about 150° F. (66° C.),suitably about 115° F. (46° C.) to about 145° F. (63° C.), and justbelow the pressure of the first hydrocracking reactor 40 and the hotseparator 50 accounting for pressure drop through intervening equipmentto keep hydrogen and light gases in the overhead and normally liquidhydrocarbons in the bottoms. The cold separator 56 may be operated atpressures between about 3 MPa (gauge) (435 psig) and about 20 MPa(gauge) (2,901 psig). The cold separator 56 may also have a boot forcollecting an aqueous phase. The cold liquid stream in the cold bottomsline 60 may have a temperature of the operating temperature of the coldseparator 56.

The cold gaseous stream in the cold overhead line 58 is rich inhydrogen. Thus, hydrogen can be recovered from the cold gaseous stream.The cold gaseous stream in the cold overhead line 58 may be passedthrough a trayed or packed recycle scrubbing column 62 where it isscrubbed by means of a scrubbing extraction liquid such as an aqueoussolution fed by line 64 to remove acid gases including hydrogen sulfideand carbon dioxide by extracting them into the aqueous solution.Preferred aqueous solutions include lean amines such as alkanolaminesDEA, MEA, and MDEA. Other amines can be used in place of or in additionto the preferred amines. The lean amine contacts the cold gaseous streamand absorbs acid gas contaminants such as hydrogen sulfide and carbondioxide. The resultant “sweetened” cold gaseous stream is taken out froman overhead outlet of the recycle scrubber column 62 in a recyclescrubber overhead line 68, and a rich amine is taken out from thebottoms at a bottom outlet of the recycle scrubber column in a recyclescrubber bottoms line 66. The spent scrubbing liquid from the bottomsmay be regenerated and recycled back to the recycle scrubbing column 62in line 64. The scrubbed hydrogen-rich stream emerges from the scrubbervia the recycle scrubber overhead line 68 and may be compressed in arecycle compressor 70. The scrubbed hydrogen-rich stream in the scrubberoverhead line 68 may be supplemented with make-up hydrogen stream in themake-up line 20 upstream or downstream of the compressor 70. Thecompressed hydrogen stream supplies hydrogen to the first stage hydrogenstream in the first stage hydrogen line 22 and a second stage hydrogenstream in a second stage hydrogen line 166. The recycle scrubbing column62 may be operated with a gas inlet temperature between about 38° C.(100° F.) and about 66° C. (150° F.) and an overhead pressure of about 3MPa (gauge) (435 psig) to about 20 MPa (gauge) (2900 psig).

The hydrocarbonaceous hot liquid stream in the hot bottoms line 54 maybe fractionated. In an aspect, the hot liquid stream in the hot bottomsline 54 may be let down in pressure and flashed in a hot flash drum 80to provide a flash hot gaseous stream of light ends in a flash hotoverhead line 82 and a flash hot liquid stream in a flash hot bottomsline 84. The hot flash drum 80 may be in direct, downstreamcommunication with the hot bottoms line 54 and in downstreamcommunication with the first hydrocracking reactor 40. In an aspect,light gases such as hydrogen sulfide may be stripped from the flash hotliquid stream in the flash hot bottoms line 84. Accordingly, a strippingcolumn 100 may be in downstream communication with the hot flash drum 80and the hot flash bottoms line 84.

The hot flash drum 80 may be operated at the same temperature as the hotseparator 50 but at a lower pressure of between about 1.4 MPa (gauge)(200 psig) and about 6.9 MPa (gauge) (1000 psig), suitably no more thanabout 3.8 MPa (gauge) (550 psig). The flash hot liquid stream in theflash hot bottoms line 84 may be further fractionated in thefractionation section 14. The flash hot liquid stream in the flash hotbottoms line 84 may have a temperature of the operating temperature ofthe hot flash drum 80.

In an aspect, the cold liquid stream in the cold bottoms line 60 may bedirectly fractionated. In a further aspect, the cold liquid stream maybe let down in pressure and flashed in a cold flash drum 86 to separatethe cold liquid stream in the cold bottoms line 60. The cold flash drum86 may be in direct downstream communication with the cold bottoms line60 of the cold separator 56 and in downstream communication with thefirst hydrocracking reactor 40.

In a further aspect, the flash hot gaseous stream in the flash hotoverhead line 82 may be fractionated in the fractionation section 14. Ina further aspect, the flash hot gaseous stream may be cooled and alsoseparated in the cold flash drum 86. The cold flash drum 86 may separatethe cold liquid stream in line 60 and/or the flash hot gaseous stream inthe flash hot overhead line 82 to provide a flash cold gaseous stream ina flash cold overhead line 88 and a flash cold liquid stream in a coldflash bottoms line 90. In an aspect, light gases such as hydrogensulfide may be stripped from the flash cold liquid stream in the flashcold bottoms line 90. Accordingly, the stripping column 100 may be indownstream communication with the cold flash drum 86 and the cold flashbottoms line 90.

The cold flash drum 86 may be in downstream communication with the coldbottoms line 60 of the cold separator 56, the hot flash overhead line 82of the hot flash drum 80 and the first hydrocracking reactor 40. Theflash cold liquid stream in the cold bottoms line 60 and the flash hotgaseous stream in the hot flash overhead line 82 may enter into the coldflash drum 86 either together or separately. In an aspect, the hot flashoverhead line 82 joins the cold bottoms line 60 and feeds the flash hotgaseous stream and the cold liquid stream together to the cold flashdrum 86 in a cold flash feed line 92. The cold flash drum 86 may beoperated at the same temperature as the cold separator 56 but typicallyat a lower pressure of between about 1.4 MPa (gauge) (200 psig) andabout 6.9 MPa (gauge) (1000 psig) and preferably between about 3.0 MPa(gauge) (435 psig) and about 3.8 MPa (gauge) (550 psig). A flashedaqueous stream may be removed from a boot in the cold flash drum 86. Theflash cold liquid stream in the flash cold bottoms line 90 may have thesame temperature as the operating temperature of the cold flash drum 86.The flash cold gaseous stream in the flash cold overhead line 88contains substantial hydrogen that may be recovered.

The fractionation section 14 may further include the stripping column100 and a fractionation column 130. Additionally, the fractionationsection 14 may include a HPNA adsorption zone 200. The stripping column100 may be in downstream communication with a bottoms line in thefractionation section 14 for stripping volatiles from a firsthydrocracked effluent stream and a second hydrocracked effluent stream.For example, the stripping column 100 may be in downstream communicationwith the hot bottoms line 54, the flash hot bottoms line 84, the coldbottoms line 60 and/or the cold flash bottoms line 90. In an aspect, thestripping column 100 may be a vessel that contains a cold strippingcolumn 102 and a hot stripping column 104 with a wall that isolates eachof the stripping columns 102, 104 from the other. The cold strippingcolumn 102 may be in downstream communication with the firsthydrocracking reactor 40, the second hydrocracking reactor 170, the coldbottoms line 60 and, in an aspect, the flash cold bottoms line 90 forstripping the cold liquid stream. The hot stripping column 104 may be indownstream communication with the first hydrocracking reactor 40, thesecond hydrocracking reactor 170, and the hot bottoms line 54 and, in anaspect, the flash hot bottoms line 84 for stripping a hot liquid streamwhich is hotter than the cold liquid stream. The hot liquid stream maybe hotter than the cold liquid stream, by at least 25° C. and preferablyat least 50° C.

The flash cold liquid stream comprising the first hydrocracked effluentstream and the second hydrocracked effluent stream in the flash coldbottoms line 90 may be heated and fed to the cold stripping column 102at an inlet which may be in a top half of the column. The flash coldliquid stream which comprises the first hydrocracked effluent stream andthe second hydrocracked effluent stream may be stripped of gases in thecold stripping column 102 with a cold stripping media which is an inertgas such as steam from a cold stripping media line 106 to provide a coldstripper gaseous stream of naphtha, hydrogen, hydrogen sulfide, steamand other gases in a cold stripper overhead line 108 and a liquid coldstripped stream in a cold stripper bottoms line 110. The cold strippergaseous stream in the cold stripper overhead line 108 may be condensedand separated in a receiver 112. A stripper net overhead line 114 fromthe receiver 112 carries a net stripper gaseous stream for furtherrecovery of LPG and hydrogen in a light material recovery unit.Unstabilized liquid naphtha from the bottoms of the receiver 112 may besplit between a reflux portion refluxed to the top of the cold strippingcolumn 102 and a liquid stripper overhead stream which may betransported in a condensed stripper overhead line 116 to furtherrecovery or processing. A sour water stream may be collected from a bootof the overhead receiver 112.

The cold stripping column 102 may be operated with a bottoms temperaturebetween about 149° C. (300° F.) and about 288° C. (550° F.), preferablyno more than about 260° C. (500° F.), and an overhead pressure of about0.35 MPa (gauge) (50 psig), preferably no less than about 0.70 MPa(gauge) (100 psig), to no more than about 2.0 MPa (gauge) (290 psig).The temperature in the overhead receiver 112 ranges from about 38° C.(100° F.) to about 66° C. (150° F.) and the pressure is essentially thesame as in the overhead of the cold stripping column 102.

The cold stripped stream in the cold stripper bottoms line 110 maycomprise predominantly naphtha and kerosene boiling materials. The coldstripped stream in line 110 may be heated and fed to the fractionationcolumn 130. The fractionation column 130 may be in downstreamcommunication with the first hydrocracking reactor 40 and the secondhydrocracking reactor 170, the cold stripper bottoms line 110 of thecold stripping column 102 and the stripping column 100. In an aspect,the fractionation column 130 may comprise more than one fractionationcolumn. The fractionation column 130 may be in downstream communicationwith one, some or all of the hot separator 50, the cold separator 56,the hot flash drum 80 and the cold flash drum 86.

The flash hot liquid stream comprising a hydrocracked stream in the hotflash bottoms line 84 may be fed to the hot stripping column 104 near atop thereof. The flash hot liquid stream may be stripped in the hotstripping column 104 of gases with a hot stripping media which is aninert gas such as steam from a line 120 to provide a hot stripperoverhead stream of naphtha, hydrogen, hydrogen sulfide, steam and othergases in a hot stripper overhead line 118 and a liquid hot strippedstream in a hot stripper bottoms line 122. The hot stripper overheadline 118 may be condensed and a portion refluxed to the hot strippingcolumn 104. However, in the embodiment of FIG. 1, the hot stripperoverhead stream in the hot stripper overhead line 118 from the overheadof the hot stripping column 104 may be fed into the cold strippingcolumn 102 directly in an aspect without first condensing or refluxing.The inlet for the cold flash bottoms line 90 carrying the flash coldliquid stream may be at a higher elevation than the inlet for the hotstripper overhead line 118. The hot stripping column 104 may be operatedwith a bottoms temperature between about 160° C. (320° F.) and about360° C. (680° F.) and an overhead pressure of about 0.35 MPa (gauge) (50psig), preferably about 0.70 MPa (gauge) (100 psig), to about 2.0 MPa(gauge) (292 psig).

At least a portion of the hot stripped stream comprising a hydrocrackedstream in the hot stripped bottoms line 122 may be heated and fed to thefractionation column 130. The fractionation column 130 may be indownstream communication with the hot stripped bottoms line 122 of thehot stripping column 104. The hot stripped stream in line 122 may be ata hotter temperature than the cold stripped stream in line 110.

In an aspect, the hot stripped stream in the hot stripped bottoms line122 may be heated and fed to a prefractionation separator 124 forseparation into a vaporized hot stripped stream in a prefractionationoverhead line 126 and a liquid hot stripped stream in a prefractionationbottoms line 128. The vaporous hot stripped stream may be fed to thefractionation column 130 in the prefractionation overhead line 128. Theliquid hot stripped stream may be heated in a fractionation furnace andfed to the fractionation column 130 in the prefractionation bottoms line128 at an elevation below the elevation at which the prefractionationoverhead line 126 feeds the vaporized hot stripped stream to thefractionation column 130.

The fractionation column 130 may be in downstream communication with thecold stripping column 102 and the hot stripping column 104 and maycomprise more than one fractionation column for separating strippedhydrocracked streams into product streams. The fractionation column 130may fractionate hydrocracked streams, the cold stripped stream, thevaporous hot stripped stream and the liquid hot stripped stream, with aninert stripping media stream such as steam from line 132 to provideplurality of fractionator product streams and a fractionator bottomsstream comprising unconverted hydrocarbons. The product streams from thefractionation column 130 may include a net fractionated overhead streamcomprising naphtha in a net overhead line 134, an optional heavy naphthastream in line 136 from a side cut outlet, a kerosene stream carried inline 138 from a side cut outlet and a diesel stream in line 140 from aside cut outlet.

The fractionator bottoms stream comprising unconverted hydrocarbonsboiling above the diesel cut point may be taken in a fractionatorbottoms line 142 from a bottom of the fractionation column 130. At leasta portion of the fractionator bottoms stream may be recycled for furtherhydrocracking, which in the instant embodiment of FIG. 1 as discussed,occurs in the second hydrocracking reactor 170. The fractionator bottomsstream being recycled may range from about 10 to about 100 wt % of afresh feed rate, preferably between about 30 and about 70 wt % of thefresh feed rate. In accordance with an exemplary embodiment as shown inFIG. 1, a first stream in a first fractionator bottoms line 202 may betaken from the fractionator bottoms stream in the fractionator bottomsline 142. Further, a second stream in a second fractionator bottoms line204 may be taken from the fractionator bottoms stream in thefractionator bottoms line 142. Accordingly, the fractionator bottomsstream may be split to provide the first stream in line 202 and thesecond stream in line 204. Therefore, in accordance with variousembodiments, the first fractionator bottoms line 202 and the secondfractionator bottoms line 204 may be fluidly connected to thefractionator bottoms line 142. In various embodiments, a third streammay be taken in a bottoms purge line 205 from the fractionator bottomsline 142 and may be rejected as a bleed stream. The first stream, thesecond stream and the third stream may be taken as aliquot portions ofthe fractionator bottoms stream.

The first stream in line 202 may be passed through the HPNA adsorptionzone 200 to obtain a treated bottoms stream in line 206 having a reducedconcentration of HPNA compounds. Accordingly, the HPNA adsorption zone200 may be in downstream communication with the first fractionatorbottoms line 202 and the fractionator bottoms line 142. In the HPNAadsorption zone 200, the first stream may be contacted with a suitableadsorbent, which may selectively retain the HPNA compounds. Suitableadsorbents may include one or more of a molecular sieve, a silica gel,an activated carbon, an activated alumina, a silica-alumina gel, and aclay. In one example, the HPNA adsorption zone 200 may comprise anactivated carbon. The adsorbent may be installed in the adsorption zone200 in any suitable manner, such as a fixed bed arrangement. Theadsorbent may be installed in one or more vessels and either in seriesor parallel flow. The HPNA adsorption zone 200 may be operated in aswing bed or in a lead-lag configuration. The HPNA adsorption zone 200can be maintained at a pressure from about 170 kPa (25 psig) to about4,300 kPa (624 psig), a temperature from about 10° C. (50° F.), to about370° C. (698° F.), and an LHSV from about 0.1 to about 500 hr⁻¹. Theflow of the first stream through the HPNA adsorption zone 200 may beconducted in an upflow, downflow or radial flow manner with thehydrocarbons in the liquid phase.

In accordance with an exemplary embodiment, the first stream in line 202passing through the HPNA adsorption zone 200 may be between 2 to 10% ofthe fresh feed rate. The second stream in line 204 may be passed aroundthe HPNA adsorption zone 200. Accordingly, the second stream and thesecond fractionator bottoms line 204 bypasses and may be out ofcommunication with the HPNA adsorption zone 200.

The treated bottoms stream in line 206 and the bypassed second stream inline 204 may be subsequently hydrocracked. Accordingly, the process mayinclude hydrocracking the treated bottoms stream and the bypassed secondstream. In accordance with an exemplary embodiment as shown in FIG. 1,the treated bottoms stream and the bypassed second stream may becombined in a line 208 and passed to the second hydrocracking reactor170 present in the second stage hydrocracking unit 150. In an aspect,the treated bottoms stream and the bypassed second stream may combine asa feed stream to the second stage hydrocracking unit 150. In accordancewith an exemplary embodiment, the treated bottoms stream and thebypassed second stream may pass through a hydrotreating reactor (notshown) prior to being passed to the second hydrocracking reactor 170.

Heat may be removed from the fractionation column 130 by cooling atleast a portion of the product streams and sending a portion of eachcooled stream back to the fractionation column. These product streamsmay also be stripped to remove light materials to meet product purityrequirements. A fractionated overhead stream in an overhead line 148 maybe condensed and separated in a receiver 150 with a portion of thecondensed liquid being refluxed back to the fractionation column 130.The net fractionated overhead stream in line 134 may be furtherprocessed or recovered as naphtha product. The fractionation column 130may be operated with a bottoms temperature between about 260° C. (500°F.), and about 385° C. (725° F.), preferably at no more than about 350°C. (650° F.), and at an overhead pressure between about 7 kPa (gauge) (1psig) and about 69 kPa (gauge) (10 psig). A portion of the unconvertedoil stream in the atmospheric bottoms line 142 may be reboiled andreturned to the fractionation column 130 instead of adding an inertstripping media stream such as steam in line 132 to heat to thefractionation column 130.

The combined stream in line 208 may be mixed with a second hydrotreatinghydrogen stream in a second hydrocracking hydrogen line 152 to providesecond hydrocracker feed stream in a second hydrocracker feed line 154.The second hydrocracker feed stream may be heated by heat exchange witha second hydrocracked effluent stream in line 46 and in a fired heaterbefore being passed to the second hydrocracking reactor 170. The secondhydrocracker feed stream is fed through a first inlet 162 i to thesecond hydrocracking reactor 170 to be hydrocracked.

The second hydrocracking reactor 170 may be a fixed bed reactor thatcomprises one or more vessels, single or multiple catalyst beds 172 ineach vessel, and various combinations of hydrotreating catalyst,hydroisomerization catalyst and/or hydrocracking catalyst in one or morevessels. It is contemplated that the second hydrocracking reactor 170 beoperated in a continuous liquid phase in which the volume of the liquidhydrocarbon feed is greater than the volume of the hydrogen gas. Thesecond hydrocracking reactor 170 may also be operated in a conventionalcontinuous gas phase, a moving bed or a fluidized bed hydroprocessingreactor.

The second hydrocracker feed stream in the second hydrocracker feed line154 is hydrocracked over the second hydrocracking catalyst in the secondhydrocracking catalyst beds 172 in the presence of hydrogen to provide asecond hydrocracked effluent stream. Subsequent catalyst beds 172 in thehydrocracking reactor may comprise hydrocracking catalyst over whichadditional hydrocracking occurs. Hydrogen manifold 176 may deliversupplemental hydrogen streams to one, some or each of the catalyst beds172. In an aspect, the supplemental hydrogen is added to each of thedownstream catalyst beds 172 at an interstage location between adjacentbeds, so supplemental hydrogen is mixed with hydrocracked effluentexiting from the upstream catalyst bed 172 before entering thedownstream catalyst bed 172.

The second hydrocracking reactor 170 may provide a total conversion ofat least about 1 vol % and typically greater than about 40 vol % of thesecond hydrocracking feed stream in the second hydrotreating effluentline 162 to products boiling below the diesel cut point. The secondhydrocracking reactor 170 may complete the conversion partially achievedin the first hydrocracking reactor 40. The second hydrocracking reactor170 may operate at partial conversion of more than about 30 vol % orfull conversion of at least about 90 vol % of the first hydrocrackingfeed stream in the first hydrocracking feed line 32 based on totalconversion. The second hydrocracking reactor 170 may be operated at mildhydrocracking conditions which will provide about 1 to about 60 vol %,preferably about 20 to about 50 vol %, total conversion of thehydrocarbon feed stream to product boiling below the diesel cut point.

The second hydrocracking reactor 170 comprises a plurality of catalystbeds 172. In accordance with various embodiments, the first catalyst bedin the hydrocracking reactor 170 may include a hydrotreating catalystfor the purpose of saturating aromatic rings in the second hydrocrackerfeed stream in the second hydrocracker feed line 154 before it ishydrocracked with the second hydrocracking catalyst in subsequentvessels or catalyst beds 172 in the second hydrocracking reactor 170.

The second hydrocracking catalyst may be the same as or different thanthe first hydrocracking catalyst or may have some of the same as andsome different than the first hydrocracking catalyst in the firsthydrocracking reactor 40. The second hydrocracking catalyst may utilizeamorphous silica-alumina bases or low-level zeolite bases combined withone or more Group VIII or Group VIB metal hydrogenating components.Additional hydrogenating components may be selected from Group VIB forincorporation with the zeolite base.

By one approach, the hydrocracking conditions in the secondhydrocracking reactor 170 may be the same as or different than in thefirst hydrocracking reactor 40. Conditions in the second hydrocrackingreactor may include a temperature from about 290° C. (550° F.) to about468° C. (875° F.), preferably 343° C. (650° F.) to about 445° C. (833°F.), a pressure from about 4.8 MPa (gauge) (700 psig) to about 20.7 MPa(gauge) (3000 psig), a liquid hourly space velocity (LHSV) from about0.4 to less than about 2.5 hr⁻¹ and a hydrogen rate of about 421 Nm³/m³(2,500 scf/bbl) to about 2,527 Nm³/m³ oil (15,000 scf/bbl).

The second hydrocracked effluent stream may exit the secondhydrocracking reactor 170 in the second hydrocracked effluent line 46,be heat exchanged with the second hydrocracker feed stream in the secondhydrocracker feed line 154 and combined with the first hydrocrackedeffluent stream in first hydrocracked effluent line 48. The firsthydrocracked effluent stream and the second hydrocracked effluent streamcombined in combined hydrocracked effluent line 49 are separated andfractionated in the fractionation section 14 in downstream communicationwith the second hydrocracking reactor 170 as previously described.

FIG. 2 shows an embodiment of the apparatus and process 10′ thatillustrates a single hydrocracking unit. Elements in FIG. 2 with thesame configuration as in FIG. 1 will have the same reference numeral asin FIG. 1. Elements in FIG. 2 which have a different configuration asthe corresponding element in FIG. 1 will have the same reference numeralbut designated with a prime symbol (′). The configuration and operationof the embodiment of FIG. 2 is essentially the same as in FIG. 1 withthe following exceptions.

The process and apparatus 10′ does not comprise a second stagehydrocracking unit 150. Accordingly, the treated bottoms stream in line206 and the bypassed second stream in line 204 may be combined in a line208′ and passed back to the hydrocracking reactor 40. In an aspect, thetreated bottoms stream and the bypassed second stream may combine in acombined stream to the hydrocracking unit 12′. In accordance with anexemplary embodiment as shown in FIG. 2, the combined stream in line208′ may be mixed with the hydrocarbon line 18′ to provide thehydrocarbon feed stream in the hydrocarbon feed line 26′ which issubsequently processed as described in FIG. 1. In an aspect, thecombined stream in line 208′ may bypass the hydrotreating reactor 30 andis provided to the hydrotreating effluent line 32 and passed to thehydrocracking reactor 40 for further processing a described in FIG. 1.

By splitting the fractionator bottoms stream, the present process andapparatus allows the operator to tailor the operation for the actualHPNA removal requirements as operating severity and feed changes. If theunit is processing a feed high in HPNA precursors, the operator has theoption to increase the flow to the HPNA adsorption zone by reducing thebypass. Likewise, during periods of feeds low in HPNA precursors, theflow to the chambers could be reduced by increasing the bypass. Further,as the flow to the HPNA adsorption zone is reduced, this results insmaller activated carbon chamber and reduced frequency of activatedcarbon replacement.

SPECIFIC EMBODIMENTS

While the following is described in conjunction with specificembodiments, it will be understood that this description is intended toillustrate and not limit the scope of the preceding description and theappended claims.

A first embodiment of the invention is a process of removing HPNAcompounds from a hydrocracked stream, the process comprising passing atleast a portion of the hydrocracked stream to a fractionation column toprovide a plurality of fractionator product streams and a fractionatorbottoms stream comprising unconverted hydrocarbons; taking a firststream from the fractionator bottoms stream; taking a second stream fromthe fractionator bottoms stream; passing the first stream through a HPNAadsorption zone to obtain a treated bottoms stream having a reducedconcentration of HPNA compounds; bypassing the second stream around theHPNA adsorption zone; and hydrocracking the treated bottoms stream andthe bypassed second stream. An embodiment of the invention is one, anyor all of prior embodiments in this paragraph up through the firstembodiment in this paragraph further comprising hydrocracking ahydrocarbon feedstream in a first hydrocracking reactor, wherein thehydrocarbon feedstream is contacted with a first hydrocracking catalystunder first hydrocracking conditions in the presence of hydrogen toprovide the hydrocracked stream. An embodiment of the invention is one,any or all of prior embodiments in this paragraph up through the firstembodiment in this paragraph, wherein the step of hydrocracking thetreated bottoms stream and the bypassed second stream occurs in thefirst hydrocracking reactor. An embodiment of the invention is one, anyor all of prior embodiments in this paragraph up through the firstembodiment in this paragraph, wherein the step of hydrocracking thetreated bottoms stream and the bypassed second stream occurs in a secondhydrocracking reactor. An embodiment of the invention is one, any or allof prior embodiments in this paragraph up through the first embodimentin this paragraph, wherein the HPNA adsorption zone comprises anactivated carbon. An embodiment of the invention is one, any or all ofprior embodiments in this paragraph up through the first embodiment inthis paragraph further comprising hydrotreating the hydrocarbonfeedstream in a hydrotreating reactor prior to hydrocracking thehydrocarbon feedstream in the first hydrocracking reactor. An embodimentof the invention is one, any or all of prior embodiments in thisparagraph up through the first embodiment in this paragraph, wherein thetreated bottoms stream and the bypassed second stream are passed throughthe hydrotreating reactor prior to the step of hydrocracking. Anembodiment of the invention is one, any or all of prior embodiments inthis paragraph up through the first embodiment in this paragraph furthercomprising passing the hydrocracked stream through one or morevapor-liquid separators to provide a recycle hydrogen gas stream and atleast one liquid process stream; and passing the at least one liquidprocess stream to the fractionation column to provide the plurality offractionator product streams and the fractionator bottoms stream. Anembodiment of the invention is one, any or all of prior embodiments inthis paragraph up through the first embodiment in this paragraph furthercomprising taking a third stream from the fractionator bottoms streamand rejecting the third stream as a bleed stream.

A second embodiment of the invention is a process for upgrading ahydrocarbon stream, the process comprising passing the hydrocarbonfeedstream to a first hydrocracking reactor, the first hydrocrackingreactor containing at least one bed of a first hydrocracking catalyst,wherein the hydrocarbon feedstream is contacted with the firsthydrocracking catalyst under first hydrocracking conditions in thepresence of hydrogen to produce a first hydrocracked effluent stream;passing at least a portion of the first hydrocracked effluent stream toa fractionation column to provide a plurality of fractionator productstreams and a fractionator bottoms stream comprising unconvertedhydrocarbons; splitting the fractionator bottoms stream to provide afirst stream and a second stream; passing the first stream through aHPNA adsorption zone to obtain a treated bottoms stream having a reducedconcentration of HPNA compounds; bypassing the second stream around theHPNA adsorption zone; and passing the treated bottoms stream and thebypassed second stream to a second hydrocracking reactor, the secondhydrocracking reactor containing at least one bed of a secondhydrocracking catalyst, wherein the treated bottoms stream and thebypassed second stream are contacted with a second hydrocrackingcatalyst under second hydrocracking conditions in the presence ofhydrogen to provide a second hydrocracked effluent stream. An embodimentof the invention is one, any or all of prior embodiments in thisparagraph up through the second embodiment in this paragraph, whereinthe HPNA adsorption zone comprises an activated carbon. An embodiment ofthe invention is one, any or all of prior embodiments in this paragraphup through the second embodiment in this paragraph further comprisinghydrotreating the hydrocarbon feedstream in a hydrotreating reactorprior to hydrocracking the hydrocarbon feedstream in the firsthydrocracking reactor. An embodiment of the invention is one, any or allof prior embodiments in this paragraph up through the second embodimentin this paragraph, wherein the treated bottoms stream and the bypassedsecond stream are passed through the hydrotreating reactor prior tobeing passed to the second hydrocracked reactor. An embodiment of theinvention is one, any or all of prior embodiments in this paragraph upthrough the second embodiment in this paragraph further comprisingpassing the first hydrocracked effluent stream through one or morevapor-liquid separators to provide a recycle hydrogen gas stream and atleast one liquid process stream; passing the at least one liquid processstream to the fractionation column to provide the plurality offractionator product streams and the fractionator bottoms stream. Anembodiment of the invention is one, any or all of prior embodiments inthis paragraph up through the second embodiment in this paragraphfurther comprising obtaining a third stream from the fractionatorbottoms stream, the third stream being rejected as a bleed stream.

A third embodiment of the invention is an apparatus for removing HPNAcompounds from a hydrocracked stream, the apparatus comprising afractionation column in communication with a hydrocracked effluent lineto provide a plurality of fractionator product streams and afractionator bottoms stream in a fractionator bottoms line; a firstfractionator bottoms line fluidly connected to the fractionator bottomsline; a second fractionator bottoms line fluidly connected to thefractionator bottoms line; a HPNA adsorption zone in downstreamcommunication with the first fractionator bottoms line to provide atreated bottoms stream in a treated bottoms line having a reducedconcentration of HPNA compounds; and a hydrocracking reactor incommunication with the treated bottoms line and the second fractionatorbottoms line, the second fractionator bottoms line bypassing the HPNAadsorption zone. An embodiment of the invention is one, any or all ofprior embodiments in this paragraph up through the third embodiment inthis paragraph, wherein the HPNA adsorption zone comprises an activatedcarbon. An embodiment of the invention is one, any or all of priorembodiments in this paragraph up through the third embodiment in thisparagraph further comprising a first hydrocracking reactor to provide ahydrocracked stream in the hydrocracked effluent line. An embodiment ofthe invention is one, any or all of prior embodiments in this paragraphup through the third embodiment in this paragraph, wherein thehydrocracking reactor is the first hydrocracking reactor. An embodimentof the invention is one, any or all of prior embodiments in thisparagraph up through the third embodiment in this paragraph, wherein thehydrocracking reactor is a second hydrocracking reactor, the secondhydrocracking reactor in downstream communication with the firsthydrocracking reactor.

Without further elaboration, it is believed that using the precedingdescription that one skilled in the art can utilize the presentinvention to its fullest extent and easily ascertain the essentialcharacteristics of this invention, without departing from the spirit andscope thereof, to make various changes and modifications of theinvention and to adapt it to various usages and conditions. Thepreceding preferred specific embodiments are, therefore, to be construedas merely illustrative, and not limiting the remainder of the disclosurein any way whatsoever, and that it is intended to cover variousmodifications and equivalent arrangements included within the scope ofthe appended claims.

In the foregoing, all temperatures are set forth in degrees Celsius and,all parts and percentages are by weight, unless otherwise indicated.

1. A process of removing heavy polynuclear aromatic (HPNA) compoundsfrom a hydrocracked stream, the process comprising: passing at least aportion of the hydrocracked stream to a fractionation column to providea plurality of fractionator product streams and a fractionator bottomsstream comprising unconverted hydrocarbons; taking a first stream fromthe fractionator bottoms stream; taking a second stream from thefractionator bottoms stream; passing the first stream through a HPNAadsorption zone to obtain a treated bottoms stream having a reducedconcentration of HPNA compounds; bypassing the second stream around theHPNA adsorption zone; and hydrocracking the treated bottoms stream andthe bypassed second stream.
 2. The process of claim 1 further comprisinghydrocracking a hydrocarbon feedstream in a first hydrocracking reactor,wherein the hydrocarbon feedstream is contacted with a firsthydrocracking catalyst under first hydrocracking conditions in thepresence of hydrogen to provide the hydrocracked stream.
 3. The processof claim 2, wherein the step of hydrocracking the treated bottoms streamand the bypassed second stream occurs in the first hydrocrackingreactor.
 4. The process of claim 2, wherein the step of hydrocrackingthe treated bottoms stream and the bypassed second stream occurs in asecond hydrocracking reactor.
 5. The process of claim 1, wherein theHPNA adsorption zone comprises an activated carbon.
 6. The process ofclaim 2 further comprising hydrotreating the hydrocarbon feedstream in ahydrotreating reactor prior to hydrocracking the hydrocarbon feedstreamin the first hydrocracking reactor.
 7. The process of claim 6, whereinthe treated bottoms stream and the bypassed second stream are passedthrough the hydrotreating reactor prior to the step of hydrocracking. 8.The process of claim 1 further comprising: passing the hydrocrackedstream through one or more vapor-liquid separators to provide a recyclehydrogen gas stream and at least one liquid process stream; and passingthe at least one liquid process stream to the fractionation column toprovide the plurality of fractionator product streams and thefractionator bottoms stream.
 9. The process of claim 1 furthercomprising taking a third stream from the fractionator bottoms streamand rejecting the third stream as a bleed stream.
 10. A process forupgrading a hydrocarbon stream, the process comprising: passing thehydrocarbon feedstream to a first hydrocracking reactor, the firsthydrocracking reactor containing at least one bed of a firsthydrocracking catalyst, wherein the hydrocarbon feedstream is contactedwith the first hydrocracking catalyst under first hydrocrackingconditions in the presence of hydrogen to produce a first hydrocrackedeffluent stream; passing at least a portion of the first hydrocrackedeffluent stream to a fractionation column to provide a plurality offractionator product streams and a fractionator bottoms streamcomprising unconverted hydrocarbons; splitting the fractionator bottomsstream to provide a first stream and a second stream; passing the firststream through a HPNA adsorption zone to obtain a treated bottoms streamhaving a reduced concentration of HPNA compounds; bypassing the secondstream around the HPNA adsorption zone; and passing the treated bottomsstream and the bypassed second stream to a second hydrocracking reactor,the second hydrocracking reactor containing at least one bed of a secondhydrocracking catalyst, wherein the treated bottoms stream and thebypassed second stream are contacted with a second hydrocrackingcatalyst under second hydrocracking conditions in the presence ofhydrogen to provide a second hydrocracked effluent stream.
 11. Theprocess of claim 10, wherein the HPNA adsorption zone comprises anactivated carbon.
 12. The process of claim 10 further comprisinghydrotreating the hydrocarbon feedstream in a hydrotreating reactorprior to hydrocracking the hydrocarbon feedstream in the firsthydrocracking reactor.
 13. The process of claim 10, wherein the treatedbottoms stream and the bypassed second stream are passed through thehydrotreating reactor prior to being passed to the second hydrocrackedreactor.
 14. The process of claim 10 further comprising: passing thefirst hydrocracked effluent stream through one or more vapor-liquidseparators to provide a recycle hydrogen gas stream and at least oneliquid process stream; passing the at least one liquid process stream tothe fractionation column to provide the plurality of fractionatorproduct streams and the fractionator bottoms stream.
 15. The process ofclaim 10 further comprising obtaining a third stream from thefractionator bottoms stream, the third stream being rejected as a bleedstream.
 16. An apparatus for removing HPNA compounds from a hydrocrackedstream, the apparatus comprising: a fractionation column incommunication with a hydrocracked effluent line to provide a pluralityof fractionator product streams and a fractionator bottoms stream in afractionator bottoms line; a first fractionator bottoms line fluidlyconnected to the fractionator bottoms line; a second fractionatorbottoms line fluidly connected to the fractionator bottoms line; a HPNAadsorption zone in downstream communication with the first fractionatorbottoms line to provide a treated bottoms stream in a treated bottomsline having a reduced concentration of HPNA compounds; and ahydrocracking reactor in communication with the treated bottoms line andthe second fractionator bottoms line, the second fractionator bottomsline bypassing the HPNA adsorption zone.
 17. The apparatus of claim 16,wherein the HPNA adsorption zone comprises an activated carbon.
 18. Theapparatus of claim 16 further comprising a first hydrocracking reactorto provide a hydrocracked stream in the hydrocracked effluent line. 19.The apparatus of claim 16, wherein the hydrocracking reactor is thefirst hydrocracking reactor.
 20. The apparatus of claim 16, wherein thehydrocracking reactor is a second hydrocracking reactor, the secondhydrocracking reactor in downstream communication with the firsthydrocracking reactor.